Large amounts of oil and gas are located in unconventional reservoirs such as shale formations. Shale formations are tight-rock formations that have reasonable porosity (3-8%) but low permeability (i.e., less than about 0.1 milli-darcy rocks). Unlike traditional oil and gas reservoirs, shale formations produce oil and gas from rock formations with flows which, in some cases, are less permeable than concrete.
By the early 2000s, the oil and gas industry showed it could produce oil and gas economically from shale formations. Bringing shale formations into production required innovations in both drilling (e.g., long horizontal wells) and hydraulic fracturing (e.g., high-pressure, high-volume, isolated, multi-staged injections). Hydraulic fracturing creates networks of micro-fractures which extend great distances from the wellbore. The production flows through these micro crack networks linking the porosity to larger fractures near the wellbore.
Understanding the behavior of pressurized micro-cracks is critical to understanding, managing, and predicting production behavior and lifetime of shale formations. These, in turn, are important to the economic success of any field or reservoir. The characteristics of oil flow through highly flow-restrictive shales is not as well understood and has not been accurately quantified compared to conventional oil reservoirs.
Understanding the role of micro-fractures in the development, production, and management of shale formations requires measurement and quantification of the flow and phase behavior of the hydrocarbons and any other fluids in the micro-fractures and the nearby pores. As production develops, pressure in the reservoir changes and a rich gas may condense into liquid in the nano-pores adjacent to a micro fracture, reducing (or otherwise changing) the rate of mass transfer.
Quantifying pressure and the pressure-dominated changes and including that data in reservoir simulation models would be very useful to managing, maintaining, and optimizing production. Unfortunately, at present, there is no device or sensor known that can make quantitative pressure measurements in the micro-scale flow channels that are experienced in shale formations.
More specifically, conventional pressure measurement systems couple directly into the fluid where the measurement is needed. Stated differently, a sensing element of the measurement system is connected to, or inserted in, the fluid. The pressure of the fluid physically displaces or deflects the sensing element. The measurement system then either converts the deflection or displacement to a pressure reading or sends a signal to a readout or recording device. The key to these conventional systems is the direct coupling between the measurement system and the targeted fluid.
Conventional systems are intrusive and are thus normally applicable for measuring pressure only in large applications which allow the necessary system-fluid coupling. These conventional systems are not applicable for small applications since, by coupling with the fluid, they deform the setup and corrupt the measurements. For example, these conventional systems may alter the pressure of the fluid being measured. In some cases, the sensing element of the conventional system is simply too large to directly couple to fluids in small chambers, such as the nano-pores and a micro fractures within shale production fields. Thus, known pressure measuring systems are not applicable for pressure measurements needed in small cracks or small crack networks.
Because conventional systems cannot make quantitative pressure measurements in micro-scale flow channels, flow and phase characteristics within micro-fractures are currently visualized and measured using specialized porous media micro models. However, pressure as a controlling variable cannot be directly measured by these models. Hence this data must be recorded in laboratory simulations. One drawback of these laboratory simulations is that they are costly, crude, time consuming to employ, and inaccurate.
An example of one simulation system is the Automated Centrifuge System-ACES-300 by Corelabs. The ACES-300 utilizes centrifugal methods to measure capillary pressure inside core samples obtained from a producing formation during drilling. This system does not consider how characteristics of the core sample may change during actual production of the related reservoir. The conventional pressure measurement system employed by the oil and gas industry and the porous media research community measures fluid pressure on the scale of hard-to-recover core samples. Conventional systems, unfortunately, cannot identify pressure within individual pores. Further, conventional systems do not give any information about fluid movement as the reservoir condition changes through production and enhance oil recovery (EOR) operations. Thus, the data from flow tests of cores captured during drilling give very imprecise and inaccurate data about initial reservoir conditions and is not indicative of how production may change during the lifetime of the reservoir.
Further background information can be found in: Birch, Downs, An updated Edlén Equation for the Refractive Index of Air, Metrologia 30:155-163, 1993, available at http://iopscience.iop.org/article/10.1088/0026-1394/30/3/004/meta;jsessionid=DAC59C333911E92EA3800B892EBFAD2D.c2.iopscience.cld.iop.org; and Bengt Edlén, The Refractive Index of Air, Metrologia, 2:71-80, 1966, available at http://iopscience.iop.org/article/10.1088/0026-1394/2/2/002/meta which are each incorporated herein by reference in their entirety. To provide additional background and context, the following references are incorporated by reference herein in their entireties: U.S. Pat. Nos. 5,218,197; 6,130,439; 7,130,060; and 8,502,985.
Due to the limitations associated with conventional pressure measurement systems and modeling techniques there is an unmet need for a system and method of measuring pressure and phase changes in a fluid that does not require coupling directly to the fluid.